pricing methodology for gas transmission services · price component: the various tariffs, fees and...

Pricing Methodology for Gas

Transmission Services

Effective from 1 October 2015

Pursuant to: the Gas Transmission Information Disclosure Determination 2012, NZCC24,

1 October 2012.

Pricing Methodology for Gas Transmission Services

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Contents

CONTENTS ............................................................................................................. I

GLOSSARY .......................................................................................................... III

EXECUTIVE SUMMARY .......................................................................................... 1

SECTION 1 OVERVIEW ...................................................................................... 2

ABOUT VECTOR .............................................................................................. 2

BACKGROUND ................................................................................................ 2

APPLICABLE REGULATIONS .................................................................................. 4

ADDITIONAL DISCLOSURES ................................................................................. 4

PRICE SETTING POLICY FRAMEWORK ....................................................................... 4

1.5.1. Economic, commercial and practical drivers............................................... 4

CONSULTATION PROCESS ................................................................................... 5

SECTION 2 COMMERCIAL PRICE-SETTING FRAMEWORK ................................... 7

COMPETITIVE PRESSURES ON PRICING .................................................................... 7

PRICING AGAINST ALTERNATIVE ENERGY SOURCES....................................................... 7

SECTION 3 METHODOLOGY FOR STANDARD PRICES ......................................... 9

PRICING REGIONS ........................................................................................... 9

COST CATEGORIES ........................................................................................ 10

3.2.1. Total allocable cost............................................................................... 10

3.2.2. Connection costs .................................................................................. 11

3.2.3. Shared costs ....................................................................................... 13

COST ALLOCATION MODEL FOR SHARED COSTS ......................................................... 13

3.3.1. Expense categories .............................................................................. 13

3.3.2. Cost allocation ..................................................................................... 15

3.3.3. Adjustments ........................................................................................ 18

3.3.4. Total allocated costs by pricing region .................................................... 18

PRICE SETTING AND THE ALLOCATION OF TARGET REVENUE ........................................... 18

3.4.1. Target revenue .................................................................................... 18

3.4.2. Setting prices ...................................................................................... 19

3.4.3. Target revenue by pricing region ........................................................... 19

3.4.4. Revenue by price component ................................................................. 20

PRICE CHANGES ........................................................................................... 21

SECTION 4 CONSISTENCY WITH PRICING PRINCIPLES .................................. 23

PRICING PRINCIPLES ...................................................................................... 23

PRINCIPLE #1: ECONOMIC COSTS OF SERVICE PROVISION ........................................... 23


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4.2.1. Subsidy-free pricing ............................................................................. 23

4.2.2. Available service capacity and future investment costs ............................. 29

PRINCIPLE #2: RECOVERY OF ANY SHORTFALL ........................................................ 29

PRINCIPLE #3: RESPONSIVE TO REQUIREMENTS OF CONSUMERS .................................... 29

4.4.1. Prices discourage uneconomic bypass ..................................................... 29

4.4.2. Negotiation for non-standard prices........................................................ 30

PRINCIPLE #4: PRICING PROCESS ...................................................................... 30

4.5.1. Development of prices is transparent ..................................................... 30

4.5.2. Price stability and certainty ................................................................... 30

4.5.3. Effect on consumers ............................................................................. 31

SECTION 5 PRICING FOR NON-STANDARD CONTRACTS .................................. 32

EXTENT OF NON-STANDARD CONTRACTS ................................................................ 32

CRITERIA FOR NON-STANDARD CONTRACTS ............................................................ 32

METHODOLOGY FOR NON-STANDARD PRICES ........................................................... 33

OBLIGATIONS IN RESPECT OF SERVICE INTERRUPTIONS ............................................... 34

SECTION 6 COMPLIANCE MATRIX ................................................................... 36


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Glossary

Act: the Commerce Act 1986.

Allowable notional revenue: the revenue Vector determined under the GDPP that Vector

is allowed to earn during the pricing year.

Authorisation: the Commerce Act (Vector Natural Gas Services) Authorisation 2008.

Connection Point (CP): an aggregation of one or more Delivery Points (DPs) for cost

allocation purposes.

COSM: Cost of Supply Model.

CPI: the Consumers Price Index, a measure of changes to the prices for consumer items

purchased by New Zealand households giving a measure of inflation.

CRF: Capacity reservation fee, a charge applied for reserved capacity.

Delivery Point: means a point at which a shipper’s gas is taken (or made available to be

taken) from a pipeline into another pipeline, another transmission pipeline (whether owned

by a shipper or a third party), a shipper’s gas consuming facility or a distribution network.

Determination: the Gas Information Disclosure Determination 2012.

DP: Delivery Point.

GDPP: Gas Transmission Default Price Path.

GJ: Gigajoule, a unit of energy.

GTPM: Gas Transmission Pricing Methodology.

Incremental Cost (IC): the cost of providing a defined service to an additional consumer

or group of consumers given that service is already provided to other consumers.

NGC: Natural Gas Corporation.

NSFA: Non-system fixed assets.

Price Component: the various tariffs, fees and charges that constitute the components of

the total price paid, or payable, by a consumer.

Pricing Principles: the pricing principles specified in clause 2.5.2 of the Gas Transmission

Services Input Methodologies Determination 2010 (Commerce Commission Decision 712,

22 December 2010).

Pricing Strategy: a decision made by the Directors of a gas transmission business on the

gas transmission business’s plans or strategy to amend or develop prices in the future, and

recorded in writing.

Pricing Year: the annual period beginning on 1 October and ending on 30 September.

RAB: Regulatory Asset Base, the regulated value of the assets that Vector uses to provide

gas transmission services.

scm/h: a measure of gas consumption “standard cubic metres per hour”.

SFA: System Fixed Assets.

Stand Alone Cost (SAC): the cost of providing a defined service or group of services to a

particular consumer or group of consumers, without providing any other services or

serving any other consumers.


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Target revenue: the revenue Vector expects to receive from prices during the pricing

year.

TOU: Time of use.

TPF: Throughput fee, a charge applied to gas conveyed.

VTC: the Vector Transmission Code.


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Executive summary

This document describes Vector’s Gas Transmission Pricing Methodology (GTPM). It

provides information for interested parties to understand how our gas transmission prices

are set and provides context about the development of our GTPM in a transparent manner.

Our focus is to provide our customers with a cost efficient, high quality service and this

document explains how we recover the cost of providing this service to our customers.

Vector’s overall revenue level is subject to the Gas Transmission Services Default Price-

Quality Path Determination 2013 (the Determination) that requires an initial starting price

adjustment applied in 2013 and a CPI-X plus pass-through price path. The Cost of Service

Model (COSM) used by Vector identifies the revenues that would be necessary from each

consumer group within the constraint of the GDPP.

Vector has also adopted a framework where the costs allocated to each consumer group

are tested against both the cost of a “stand alone” network and the cost of alternative

energy supplies. This ensures that cost allocations do not arbitrarily result in prices that

are sufficiently high that consumers have an incentive to disconnect and use alternative

energy sources. This benefits all consumers of natural gas transmission services by

providing a pricing structure that encourages broad uptake of distributed natural gas,

thereby resulting in shared network costs being spread across as many consumers as

possible.

At the same time, the pricing principles require that Vector demonstrates that prices are

not less than incremental cost, that is are “subsidy-free”. This has not been achieved for

all prices, and Vector is working towards improved estimates of incremental cost for

locations where prices are potentially below incremental costs, as well as considering a

long-term strategy that takes account of the options available to affected consumers.

Vector recognises the impact of price changes on its consumers. The development of the

GTPM was subject to an extensive consultation process in 2012 and 2013, with changes to

pricing structure only been made after considering feedback from shippers and directly

connected consumers. Vector’s weighted average prices for 2016 have increased by 2.2%,

being the combined impact of changes to CPI on the transmission component of prices

(0.8%) and increases to the pass-through and recoverable component of prices (1.4%).

Despite this relatively modest increase in weighted average prices, there has been a

significant reduction in load on the transmission system. Standard prices have therefore

increased by more than the weighted average increase (approximately 16% in total), as is

anticipated by the regulatory revenue cap regime we operate under. Vector recognises the

impact this change has on our customers and we have refrained from making any

structural changes to prices. The increase has been applied consistently to capacity

reservation fees across all delivery points.


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Section 1 Overview

1.1. About Vector

Vector is a leading New Zealand infrastructure group. We own and manage a unique

portfolio of energy and fibre optic infrastructure networks in New Zealand. Our assets

perform a key role in delivering energy and communication services to more than one

million homes and businesses across New Zealand. We are a significant provider of:

a) Electricity distribution

b) Gas transmission and distribution

c) Electricity and gas metering installations and data management services

d) Natural gas and LPG, including 60.25% ownership of bulk LPG distributor Liquigas

e) Fibre optic networks in Auckland and Wellington, delivering high speed broadband

services.

f) In addition to our energy and fibre optic businesses we own:

i) A 50% share in Treescape, an arboriculture and vegetation management

company

ii) A 22.11% share in NZ Windfarms, a power generation company.

Vector is listed on the New Zealand Stock Exchange. Our majority shareholder, with a

shareholding of 75.1%, is the Auckland Energy Consumer Trust (AECT). The trust

represents its beneficiaries, who are Vector’s electricity customers in Auckland, Manukau

and parts of the Papakura region. The balance of Vector’s shares are held by individual and

institutional shareholders. Vector acquired the gas transmission system from NGC in 2005.

1.2. Background

Vector provides gas transmission services in the North Island over a network that

comprises 2,400km of pipeline. The system was largely built between 1968 and the mid-

1980s by the Natural Gas Corporation (NGC) and was purchased by Vector in 2005. The

map below shows the Vector Transmission System in blue:


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Figure 1 Vector’s gas transmission system:

Gas is taken from Vector’s transmission system at over 130 Delivery Points (DPs), all of

which are owned by Vector. They supply both distribution networks and single consumers

such as industrial plants and power stations. Vector generally contracts with only a small

number of shippers who use the transmission system. It is the shipper’s gas that Vector

moves from its source (typically in Taranaki) through the transmission system to where it

is finally consumed.

In April 2009 the Commerce Act 1986 (the Act) was amended to incorporate a price

constraint on gas transmission businesses to increase weighted average prices by no more

than CPI between 1 January 2008 and 30 June 2012. This was intended to limit prices until

the Commerce Commission made a determination on how price-quality regulation would

apply moving forward. Under the Act, Vector was limited in its ability to rebalance the

prices that had been inherited from Natural Gas Corporation which, while originally based

on a cost allocation model, had long since ceased to be cost-reflective.


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From 1 July 2013, Vector’s Transmission system is subject to regulation under the Gas

Transmission Services Default Price-Quality Path Determination 2013 (the GDPP) that

requires an initial starting price adjustment (applied in 2013) and a CPI-X plus pass-

through price path. In addition, the Gas Transmission Information Disclosure

Determination 2012 (the Determination) also requires Vector to demonstrate how (and if

not why) prices have been set consistent with prescribed pricing principles.

From December 2011 through to the publication of final prices in 2013, Vector engaged in

an extensive review of the Gas Transmission Pricing Methodology (GTPM). The outcome of

this process was a GTPM that more closely aligns with the regulated pricing principles.

1.3. Applicable regulations

This disclosure is prepared in accordance with clause 2.4 of the Gas Transmission

Information Disclosure Determination 2012, Decision NZCC24, 1 October 2012 (the

Determination). Compliance with the requirements of this clause is demonstrated in the

compliance matrix in Section 6.

Vector’s revenue for gas transmission services is set in accordance with the Gas

Transmission Services Default Price-Quality Path Determination 2013, [2013] NZCC5, 28

February 2013 (the GDPP).

The pricing principles are specified in clause 2.5.2 of the Gas Transmission Services Input

Methodologies Determination 2010 (Commerce Commission Decision 712, 22 December

2010) (the Input Methodologies).

1.4. Additional disclosures

Vector’s gas transmission prices are subject to annual approval by the Board of Directors,

and are set to comply with the GDPP and deliver the target revenue.

Vector’s Board of Directors have not recorded in writing any decision on plans or strategies

to amend or develop prices beyond the pricing year ending on 30 September 2016 and

accordingly have not approved a pricing strategy.

1.5. Price setting policy framework

1.5.1. Economic, commercial and practical drivers

In this section we highlight some of the key factors that have influenced the design of

Vector’s proposed pricing approach. The foundation of the development of the proposed

prices is based on an application of economic pricing principles, given practical, physical

and commercial constraints. It is useful to have an understanding of these factors up front,

as it assists in understanding various decisions Vector has reached in establishing the

pricing methodology.

The majority of costs to be recovered are shared costs, which cannot be specifically attributed to

particular consumers except at high levels of aggregation

The transmission system can be described as a radial network of pipes originating from a

single geographic location in Taranaki and supplying multiple connection points along each

pipes length. Given that gas must pass through each pipe from its source to supply

connections along its length a key feature of a gas transmission system is that many of the

assets used to convey gas are used by multiple shippers and many consumers.


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The shared use of a significant portion of assets has had significant implications for the

development of transmission prices. First, it means that there are substantial common

costs, so a substantial proportion of the prices paid are a recovery of common costs rather

than being directly attributable to the provision of a specific service to a connection. There

are inevitably judgements that have to be made in determining appropriate allocation

approaches. This feature has constrained the scope of the cost of supply model to high

levels of aggregation, with more general “cost reflectivity” principles applying to the

manner in which prices have been developed consistent with the aggregated cost

allocations.

There are practical limits on the sophistication of prices to improve efficiency

Vector generally contracts indirectly with consumers through gas shippers and in effect

provides a wholesale transmission services to shippers. Shippers are then free to

repackage the cost of Vector’s transmission service, meaning it is not necessarily the case

that price signals inherent in Vector’s prices make their way through to the consumer. In

any event, gas transmission costs make up only a small portion of the average consumer’s

bill, so any price signal at the transmission level will tend to be overwhelmed by energy

and distribution charges1.

1.6. Consultation process

The new GTPM was been developed as part of a lengthy consultation process with

consumers. The process of the GTPM Review is summarised in Figure 2 below.

Figure 2 Gas transmission consultation process

The December 2011 Framework paper communicated the context and objectives of the

review together with an outline of the indicative process.

The 31 May 2012 GTPM Position Paper developed an Assessment Framework to guide the

development of the GTPM. The Assessment Framework included the pricing principles that

applied under the Input Methodologies, and continues to be relevant under the GDPP.

Vector applied this framework to determine provisional price changes for 2013 which

involved an adjustment (under the existing GTPM) to improve the balance between the

fixed and variable components of charges:

uniform 25% increase in (fixed) Capacity Reservation Fee ($/GJ of reserved

capacity); and

uniform 11% reduction in (variable) Throughput Fee ($/GJ of delivered capacity).

On 31 August 2012, Vector published a Summary and Response to Submissions by

Interested Parties on the Position Paper. This included confirmation of final prices which

took into account submitter concern regarding the re-distributional impact of the

provisional price proposal on Auckland and Wellington DPs:

1 Note that gas transmission charges are paid for directly by shippers who are

generally also gas retailers.

December 2011

GTPM Framework

May 2012 GTPM Position Paper -Proposed Framework

& Provisional Prices for PY2013

August 2012

GTPM - Summary & Response to Submissions

March 2013

GTPM Cost Allocation Framework & Pricing

Methodology

May 2013

GTPM Summary of Submissions,

Provisional prices PY2014


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uniform $25/GJ increase in (fixed) Capacity Reservation Fee; and

uniform 5.7% reduction in (variable) Throughput Fee.

Relative to the percentage increase, the absolute dollar increase in Capacity Reservation

Fee (CRF) has a larger proportional impact on the lower CRFs. This applied a larger relative

increase to CRFs in (more congested) Auckland. These changes were driven primarily by a

desire to rebalance the fixed and variable charge components to better reflect underlying

costs, but also took into account the need to minimise distortions to incentives (and in

particular incentivise less consumption in constrained Auckland). The interim price change

takes the fixed:variable revenue split from approximately 60%:40% to 65%:35%.

On 28 March 2013, Vector published a consultation paper on the cost allocation framework

and methodology to apply within the pricing methodology. This paper introduced the

approach specified in sections 3.2 and 3.3 of this document. Cost allocations and prices

were prepared on a Connection Point basis.

On 31 May 2013, Vector summarised feedback received on the 28 March paper and

notified provisional prices using the revised Pricing Regions described in section 3.1.

In June 2014, Vector notified provisional prices for the 2014/15 year to shippers. The

provisional prices incorporated uniform increases to all prices. Shippers provided no

feedback on the provisional prices. On 29 August 2014, Vector notified final prices for the

2014/15 year to shippers. These prices became effective from 1 October 2014.

In June 2015, Vector notified provisional prices for the 2015/16 year to shippers. The

provisional prices incorporated uniform increases to capacity reservation fees, with an

additional increase to the throughput fee on the Frankley Road pipeline. Shippers provided

no feedback on the provisional prices. On 28 August 2015, Vector notified final prices for

the 2015/16 year to shippers. These prices became effective from 1 October 2015.


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Section 2 Commercial price-setting framework

2.1. Competitive pressures on pricing

The starting point for establishing prices for gas transmission services is a consideration of

the role of gas as a fuel. Unlike electricity, for most consumers the choice to take gas in

the first instance and at discrete points in time is discretionary. Given the substantial

costs of laying the transmission system, there is a strong commercial drive on Vector to

maintain and improve economies of density (more consumers per unit of pipeline) and

economies of scale (more GJ delivered per unit of pipeline). Improved economies of scale

and density mean that Vector can use its capital more efficiently and consumers ultimately

benefit from the sharing of common costs across a wider number of consumers or GJ

delivered. A more diverse consumer base is also in Vector’s commercial interests as it

mitigates asset stranding risks.

2.2. Pricing against alternative energy sources

A key part of Vector’s pricing methodology is testing proposed prices against the lowest

cost alternative energy source.

In 2012 Vector asked PricewaterhouseCoopers (PwC) to calculate an implied cap for gas

transmission based on the cost of alternative fuels using the approach summarised in

Figure 3. The implied cap on gas transmission cost is a proxy for the maximum price that

could be charged for gas transmission before the cost of an alternative fuel is less than the

cost of natural gas.

Figure 3 Calculation of implied transmission cost

All-in delivered cost of alternative

Less

– GST

– replacement capital expenditure (annualised)

– gas cost

– retailer margin

– gas distribution cost (if relevant)

– other costs

= Implied cap on gas transmission cost

Bottled LPG, biomass, and coal were the alternative fuels examined. For each consumer

group the lowest implied transmission cost was selected across the three fuels. As shown

in Figure 4, bottled LPG provides the implied transmission cap for domestic and

commercial consumers, and coal provides the implied transmission cap for industrial

consumers.


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Figure 4 Implied transmission caps based on the cost of alternative fuels

Consumer type Alternative fuel Implied transmission cap ($/GJ 2012)

Small domestic Bottled LPG 39.05

Medium domestic Bottled LPG 31.57

Large domestic Bottled LPG 27.75

Small commercial Bottled LPG 20.22

Medium commercial Bottled LPG 15.24

Large commercial Bottled LPG 20.09

Large industrial Coal 4.20

Very large industrial Coal 4.90

Vector has used the above to derive weighted average transmission caps for Connection

Points. The distribution of consumer types at each DP was informed by institutional

knowledge, time of use (TOU) metered consumer ratios obtained from the transmission

allocation agent as well as sample actual consumer breakdowns obtained from the Vector

distribution business line.

The implied transmission caps are incorporated into Vector’s price-setting process, with

stand-alone cost (SAC) being set to the lesser of the Implied Transmission Cap from

alternative fuels and the cost of an alternative network solution.

There are limits to the extent to which a standardised pricing schedule can take account of

the particular circumstances of individual consumers, so in certain circumstances

consumers are able to enter into a non-standard contract as described in Section 5.


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Section 3 Methodology for standard prices

This section describes the methodology that Vector has applied for calculating prices for

controlled gas transmission services.

Within the gas transmission system gas is delivered at ‘delivery points’ (DPs). However,

for pricing purposes Vector allocates costs by “Connection Point”, which is an aggregation

of one or more DPs and then into Pricing Regions. Section 3.1 provides the rationale for

the use of Connection Points and Pricing Regions, and lists all of the Pricing Regions and

Connection Points which encompass multiple DPs.

Section 3.3 describes the operation of the Cost of Service Model (COSM) that Vector uses

to allocate costs to Connection Points and pricing regions. Because Vector operates under

a revenue cap, the costs that are inputs to COSM will not necessarily add to the amount of

the revenue cap. The allocated costs are therefore used to establish the proportion of the

target revenue that is recovered from each consumer group. The allocation of target

revenue is described in Section 3.4 and any resulting price changes in Section 3.5.

3.1. Pricing regions

In its March proposals, Vector aggregated DPs at the same or close geographical location

into a single “Connection Point” on the transmission system, e.g. Edgecumbe Connection

Point combined Edgecumbe dairy factory DP and Edgecumbe town DP into one Connection

Point with a single price. This approach means that DPs which are adjacent (or nearly

adjacent) do not have different prices simply as a result of an artefact of how the cost

allocation methodology and pricing methodology work.

Figure 5 below lists all Connection Points which have multiple DPs mapped to them. The

remaining CPs have only a single DP mapped to them.

Figure 5 Aggregation of delivery points into connection points

Connection Point Delivery Points

Ammonia Urea Ballance 8201, Ballance 9625, Ballance 9626

Drury Drury 1, Drury 2

Edgecumbe Edgecumbe, Edgecumbe DF

Greater Auckland Westfield, Henderson, Papakura, Papakura B, Bruce McLaren

Greater Hamilton Temple View, Te Kowhai

Greater Mt Maunganui Mt Maunganui, Papamoa

Greater Tauranga Tauranga, Pyes Pa

Greater Waitangirua Waitangirua, Pauatahanui

Hastings Hastings , Hastings (Nova) ,

Hawera Hawera , Hawera (Nova),

Hunua Hunua , Hunua (Nova), Hunua 3

Kapuni Lactose / 306 Kapuni (Lactose et al), Kapuni 306 Delivery

Kawerau Kawerau, Kawerau (ex-Caxton), Kawerau (ex-Tasman)

Kinleith Kinleith 1, Kinleith 2 (Paper mill)

Kiwitahi Kiwitahi 1 (Peroxide), Kiwitahi 2

Marsden Marsden 1 (NZRC), Marsden 2

Morrinsville Morrinsville, Morrinsville DF

Okaiawa \ Manaia Manaia , Okaiawa

Tawa Tawa A, Tawa B (Nova)

TCC \ Stratford Stratford 2 - Peaker, Stratford 3 - Storage, TCC Power Station

Te Awamutu \ Kihikihi Kihikihi, Te Awamutu DF

Tirau Tirau, Tirau DF


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All stakeholders who submitted on Vector’s March 2013 proposals supported greater levels

of aggregation. As a consequence, for both the provisional prices notified in May 2013 and

the final prices, Vector has adopted a broader aggregation into the Pricing Regions shown

in Figure 6. This approach means that DPs in a similar geographic area do not have

different prices simply as a result of an artefact of how the cost allocation methodology

and pricing methodology work.

Figure 6 Aggregation of delivery points into pricing regions

Region Delivery points

Northland Marsden 1 (NZRC), Marsden 2, Kauri DF, Maungaturoto DF, Warkworth, Wellsford, Whangarei

Auckland Alfriston, Drury 1, Drury 2, Flat Bush, Glenbrook (Steel Mill), Greater Auckland, Otahuhu B

Power Station, Southdown Power Station, Harrisville, Hunua, Hunua (Nova), Hunua 3, Kingseat,

Pukekohe, Ramarama, Tuakau, Waitoki

Waikato north Cambridge, Horotiu, Huntly Town, Kiwitahi 1 (Peroxide), Kiwitahi 2, Matangi, Morrinsville,

Morrinsville DF, Ngaruawahia, Tatuanui DF, Te Rapa Cogen Plant, Waitoa

Hamilton Greater Hamilton, Temple View, Te Kowhai

Waikato south Kihikihi, Kinleith 1, Kinleith 2 (Paper mill), Lichfield DF, Okoroire Springs, Otorohanga, Pirongia, Putaruru, Te Awamutu DF, Te Kuiti North, Te Kuiti South, Tirau, Tirau DF, Tokoroa, Waikeria

Western Bay of Plenty

Greater Mt Maunganui, Greater Tauranga, Rangiuru

Te Puke

Eastern Bay of Plenty

Broadlands, Edgecumbe, Edgecumbe DF, Gisborne, Kawerau, Kawerau (ex-Caxton), Kawerau (ex-Tasman), Opotiki, Reporoa, Rotorua, Taupo, Te Teko, Whakatane

Taranaki Eltham, Inglewood, Kaponga, New Plymouth, Oakura, Okato, Opunake, Pokuru 2 Delivery, Pungarehu No 1, Pungarehu No 2, Stratford, Stratford 2 – Peaker, Stratford 3 – Storage, TCC

Power Station, Waitara

Manawatu-Wanganui

Hawera, Hawera (Nova), Kaitoke, Kakariki, Lake Alice, Okaiawa \ Manaia, Marton, Matapu, Mokoia, Patea, Waitotara, Wanganui, Waverley

Hawke’s Bay Ashhurst, Dannevirke, Feilding, Flockhouse, Hastings, Hastings (Nova), Kairanga, Longburn, Mangaroa, Mangatainoka, Oroua Downs, Pahiatua, Palmerston North,Takapau

Wellington Belmont, Foxton, Greater Waitangirua, Kuku, Levin, Otaki, Paraparaumu, Pauatahanui 2, Tawa

A, Tawa B (Nova), Te Horo, Waikanae

3.2. Cost categories

Within the GTPM, costs are categorised into Connection Costs and Shared Costs.

Connection Costs are the costs directly attributable to a Delivery Point or a Pricing Region;

Shared Costs account for the balance of Vector’s Total Allocable Cost.

3.2.1. Total allocable cost

The Total Allocable Costs is a proxy for target revenue, which is based on a building block

calculation of cost. The calculation of Total Allocable Cost is shown in Figure 7.


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Figure 7 Calculation of total allocable cost

System fixed assets 489,208,278

Non-system fixed assets 8,683,068

Total assets 497,891,346

Discount rate 8.18%

Return on capital 40,719,343

Depreciation

19,759,527

Fuel cost 3,717,544

Maintenance cost 13,226,973

Pass-through cost 3,907,272

Other costs -

Indirect costs 11,034,381

Total expenses 31,886,169

Regulatory tax allowance 11,234,658

Revaluation system fixed assets (6,817,274)

Total allocable cost 96,782,424

3.2.2. Connection costs

Connection Costs are the costs directly attributable to each Connection Point. This is

determined by means of a “but for” test which identifies all assets dedicated to a

Connection Point and all expenses directly associated with a Connection Point. The

question underlying the “but for” test is:

“but for the existence of this Connection Point, would these assets exist or these

costs be incurred?”

If the assets would not exist or the expenses would not be incurred but for the existence of

the Connection Point then they are connection assets and connection expenses allocated to

the Connection Point.

Once the connection assets and connection expenses have been identified, connection

costs are calculated as:

Connection costs = Discount rate x Asset value – Asset revaluation +

Depreciation

+ Connection expenses + Tax

Grouping DPs into Connection Points or pricing regions ensures that incremental costs are

not artificially lowered because connection assets are shared between multiple DPs. Figure

8 overleaf shows the calculation of Connection Costs by Pricing Region.


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Figure 8 Calculation of connection costs by pricing region

Pricing region

Dedicated

connection assets

Discount rate

Return on capital

plus depreciation

less revaluations

plus

maintenance costs

plus regulatory

tax allowance

Connection costs

Northland 12,606,580 8.18% 1,031,011 261,645 (315,164) 225,961 289,510 1,492,962

Auckland 11,855,798 8.18% 969,610 372,244 (296,395) 610,617 272,268 1,928,344

Waikato North 5,675,185 8.18% 464,137 165,443 (141,880) 226,133 130,331 844,163

Hamilton 1,584,821 8.18% 129,612 42,335 (39,621) 73,580 36,395 242,302

Waikato South 9,584,013 8.18% 783,815 260,188 (239,600) 347,533 220,097 1,372,033

Western Bay of Plenty 4,331,796 8.18% 354,270 108,817 (108,295) 124,006 99,480 578,278

Eastern Bay of Plenty 35,018,707 8.18% 2,863,956 622,623 (875,468) 435,155 804,204 3,850,470

Taranaki 12,818,082 8.18% 1,048,309 366,381 (320,452) 383,167 294,367 1,771,772

Manawatu-Wanganui 3,609,644 8.18% 295,210 150,208 (90,241) 213,429 82,895 651,501

Hawke’s Bay 7,105,088 8.18% 581,080 191,951 (177,627) 283,662 163,168 1,042,233

Wellington 5,144,433 8.18% 420,730 193,270 (128,611) 291,006 118,142 894,538

Total 109,334,148 8,941,739 2,735,105 (2,733,354) 3,214,249 2,510,857 14,668,596


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3.2.3. Shared costs

Shared Costs are those costs that are not directly attributable to a Connection Point. The

allocation of Shared Costs recovers the balance of Vector’s Total Allocable Cost. Shared

Costs are calculated as:

Figure 9 Calculation of shared costs

Component Value

Total allocable cost 96,782,424

less

Connection costs 14,668,596

Shared costs 82,113,828

Shared Costs are recovered via the Cost Allocation Methodology described in Section 3.3

below.

3.3. Cost allocation model for shared costs

Vector uses a Cost Allocation Model to allocate shared costs to each Connection Point. This

enables Vector to set prices in a cost reflective manner.

3.3.1. Expense categories

Regulatory requirement

2.4.3(4) Where applicable, identify the key components of target revenue

required to cover the costs and return on investment associated with the GTB’s

provision of gas transmission services. Disclosure must include the numerical

value of each of the components;

The categories of expense allocated by the Cost Allocation Model are:

Return on capital;

Depreciation on system fixed assets;

Revaluations of system fixed assets;

Fuel cost;

Maintenance costs;

Pass-through costs;

Indirect costs; and

Regulatory tax allowance.

Costs with a meaningful cost driver

Vector considers that the return on capital, depreciation, revaluations, maintenance costs,

and tax expenses can all be allocated on the basis of asset values (both connection assets

and allocated shared assets):

The return on capital, depreciation, and revaluations arise directly as a result of

assets and asset values;


14

Maintenance is related to assets, and it is common practice in cost allocation to

treat asset values as a proxy for assets; and

Tax expense is primarily incurred because of the Return on Assets and the

difference between regulatory depreciation and regulatory tax depreciation.

The allocation of the above costs first requires that assets are allocated to CPs.

Connection assets are allocated directly, and shared assets are allocated as described

below.

Fuel costs can also be allocated directly, as they are incurred as a direct result of DPs that

utilise either heaters or compressors. Consequently, fuel costs are allocated based on the

throughput for those DPs.

Costs requiring a proxy cost allocator

Vector considers that the following categories of cost require proxy cost allocators:

Shared network assets (i.e. System Fixed Assets);

Non-system fixed assets;

Contributions and all other revenues;

Indirect costs; and

Pass-through and other direct costs;

Any under- or over-recoveries that arise from imposing the IC and SAC bounds.

Vector’s view is that Maximum Flow is the preferred allocator for shared costs. Network

assets are sized to meet capacity requirements. As a measure of the capacity actually

used, Maximum Flow presents the strongest link to costs and, in our assessment, moves

allocation closest to what might be implied in a market. Relative to the current (distance-

based) approach, cost allocations will increase on highly utilised or constrained parts of the

network and fall on underutilised or unconstrained parts of the network. While this does

not provide a market-based capacity price, it does improve pricing signals on constrained

and unconstrained parts of the gas transmission system.

Each component of cost, its value, and the allocator for shared costs are summarised in

Figure 10.


15

Figure 10 Summary of cost category and allocator for shared costs

Cost category Total Connection Shared Allocator for shared costs

System fixed assets 489,208,278 109,334,148 379,874,130 Maximum flow

Non-system fixed assets 8,683,068 8,683,068 Maximum flow

Total assets 497,891,346 109,334,148 388,557,198

Discount rate 8.18% 8.18% 8.18%

Return on capital 40,719,343 8,941,739 31,777,604 Calculated

Depreciation 19,759,527 2,735,105 17,024,422 Maximum flow

Fuel cost 3,717,544 3,717,544 Fuel throughput

Maintenance cost 13,226,973 3,214,249 10,012,724 System fixed assets

Pass-through cost 3,907,272 3,907,272 Maximum flow

Other costs - - Maximum flow

Indirect costs 11,034,381 11,034,381 Maximum flow

Total expenses 31,886,169 3,214,249 28,671,920

Regulatory tax allowance 11,234,658 2,510,857 8,723,802 System fixed assets

Revaluation system fixed assets

(6,817,274) (2,733,354) (4,083,920) System fixed assets

Total allocable cost 93,584,189 14,668,596 82,113,828

3.3.2. Cost allocation

Following from the discussion above and Figure 7, the allocators used to allocate shared

costs are:

Maximum flow – the maximum actual flow rate recorded for the Connection Point;

System fixed assets – the total value of attributed (Connection) and allocated

(Shared) assets for the Connection Point;

Fuel throughput – the quantity of compressor and heater fuel consumed at a

Connection Point.

The value of each allocator by Pricing Region is shown in Figure 11. The table also

includes the proportional allocation to each Pricing Region for a given allocator.

Figure 12 shows the resulting allocation of shared costs by pricing region.


16

Figure 11 Cost allocators by pricing region

Pricing region Absolute value Percentage value

Maximum flow

Compressor fuel

Heater fuel Dedicated assets

Allocated shared assets

Total system fixed assets

Maximum flow

Fuel throughput

(*)

Shared system

fixed assets

System fixed assets

Northland 19,212 3,358,298 3,357,229 12,606,580 11,637,864 24,244,444 3.06% 4.79% 3.06% 4.96%

Auckland 193,519 41,492,589 15,014,802 11,855,798 117,226,220 129,082,019 30.86% 50.81% 30.86% 26.39%

Waikato North 37,293 5,997,692 6,048,541 5,675,185 22,590,613 28,265,798 5.95% 8.57% 5.95% 5.78%

Hamilton 14,233 1,373,906 1,373,906 1,584,821 8,621,784 10,206,605 2.27% 1.96% 2.27% 2.09%

Waikato South 37,255 4,067,864 4,338,133 9,584,013 22,567,594 32,151,608 5.94% 5.89% 5.94% 6.57%

Western Bay of Plenty 7,390 945,643 945,643 4,331,796 4,476,568 8,808,364 1.18% 1.35% 1.18% 1.80%

Eastern Bay of Plenty 25,430 3,936,986 3,936,986 35,018,707 15,404,481 50,423,188 4.06% 5.62% 4.06% 10.31%

Taranaki 199,875 1,000,880 20,609,935 12,818,082 121,076,310 133,894,393 31.87% 7.63% 31.87% 27.37%

Manawatu-Wanganui 15,571 2,049,054 2,045,484 3,609,644 9,432,291 13,041,935 2.48% 2.92% 2.48% 2.67%

Hawke’s Bay 27,791 3,582,044 3,566,056 7,105,088 16,834,680 23,939,769 4.43% 5.10% 4.43% 4.89%

Wellington 49,534 4,255,301 2,026,134 5,144,433 30,005,723 35,150,156 7.90% 5.36% 7.90% 7.19%

Total 627,103 72,060,258 63,262,850 109,334,148 379,874,130 489,208,278 100.00% 100.00% 100.00% 100.00%

* The ‘Fuel throughput’ allocator is calculated as (80% x the proportion of compressor fuel) + (20% x the proportion of heater fuel).


17

Figure 12 Calculation of shared costs by pricing region

Pricing region

System

fixed

assets

Non-

system

fixed assets

Subtotal

assets

Return on

capital Depreciation Fuel cost

Maintenance

cost

Pass-

through

cost

Indirect

costs

Regulatory

tax

allowance

Revaluation

system

fixed assets

Total

Allocator Maximum flow

Maximum flow

Calculated Calculated Maximum flow

Fuel throughput

Shared SFA Maximum flow

Maximum flow

Shared SFA

Shared SFA

Northland 11,637,864 266,015 11,903,879 973,542 521,562 178,058 306,751 119,704 338,050 267,263 -125,115 2,579,815

Auckland 117,226,220 2,679,528 119,905,748 9,806,323 5,253,605 1,888,926 3,089,849 1,205,754 3,405,125 2,692,098 -1,260,266 26,081,413

Waikato North 22,590,613 516,371 23,106,984 1,889,772 1,012,420 318,620 595,443 232,360 656,200 518,793 -242,865 4,980,744

Hamilton 8,621,784 197,075 8,818,859 721,238 386,394 72,850 227,253 88,681 250,441 197,999 -92,690 1,852,166

Waikato South 22,567,594 515,844 23,083,439 1,887,847 1,011,388 218,872 594,837 232,124 655,531 518,264 -242,618 4,876,245

Western Bay of Plenty 4,476,568 102,324 4,578,892 374,478 200,622 50,142 117,993 46,045 130,033 102,804 -48,126 973,991

Eastern Bay of Plenty 15,404,481 352,112 15,756,592 1,288,631 690,367 208,756 406,031 158,446 447,461 353,764 -165,609 3,387,845

Taranaki 121,076,310 2,767,532 123,843,843 10,128,394 5,426,151 283,530 3,191,330 1,245,355 3,516,960 2,780,515 -1,301,657 25,270,577

Manawatu-Wanganui 9,432,291 215,601 9,647,892 789,039 422,717 108,608 248,616 97,018 273,984 216,612 -101,404 2,055,191

Hawke’s Bay 16,834,680 384,803 17,219,483 1,408,271 754,462 189,747 443,729 173,156 489,005 386,608 -180,985 3,663,994

Wellington 30,005,723 685,863 30,691,587 2,510,068 1,344,735 199,435 790,891 308,630 871,590 689,081 -322,583 6,391,847

Total 379,874,130 8,683,068 388,557,198 31,777,604 17,024,422 3,717,544 10,012,724 3,907,272 11,034,381 8,723,802 -4,083,920 82,113,828


18

3.3.3. Adjustments

Comparison against incremental cost

Any CP that has a total allocated cost less than Short Run Incremental Cost has the value

of allocated cost reset to Short Run Incremental Cost.

Comparison against least cost alternative

As described in section 2.2, the total cost allocated to each CP is compared to the weighted

average SAC for that CP to ensure that cost allocations do not result in prices that would

provide an incentive for consumers to disconnect from the gas transmission system. Any

CPs that have a total allocated cost greater than SAC are reset to the SAC (i.e. set to the

lesser of the total allocated cost and SAC).

Reallocation of shortfall

The comparison against SAC results in a total reduction in cost allocated to some CPs of

approximately $10m. This amount is reallocated amongst CPs using Maximum Flow as the

proxy allocator, subject to the constraint that total costs allocated to each CP must not be

greater than SAC.

3.3.4. Total allocated costs by pricing region

Figure 13 shows the total allocated costs by pricing region. The allocated cost before

adjustments is the sum of connection costs (Figure 8) and allocated shared costs (Figure

12). Allocated costs are then reduced by an aggregate $15.7 million as a result of

imposing the SAC constraint. These costs are then reallocated as described above.

Figure 13 Total allocated costs by pricing region

Pricing region Connection

costs

Shared

costs

Allocated

costs before

adjustments

Impose SAC

constraint

Recoveries Allocated

cost after

adjustments

Northland 1,492,962 2,579,815 4,072,777 (24,144) 707,181 4,755,815

Auckland 1,928,344 26,081,413 28,009,757 (26,099) 7,124,175 35,107,834

Waikato North 844,163 4,980,744 5,824,907 (2,381,880) 399,736 3,842,763

Hamilton 242,302 1,852,166 2,094,468 (1,259,151) 0 835,317

Waikato South 1,372,033 4,876,245 6,248,277 (17,311) 1,375,543 7,606,510

Western Bay of Plenty 578,278 973,991 1,552,269 247,676 1,799,945

Eastern Bay of Plenty 3,850,470 3,387,845 7,238,316 1,738,930 8,977,245

Taranaki 1,771,772 25,270,577 27,042,349 (11,772,824) 692,014 15,961,540

Manawatu-Wanganui 651,501 2,055,191 2,706,691 (107,007) 588,922 3,188,606

Hawke’s Bay 1,042,233 3,663,994 4,706,227 (72,680) 1,007,771 5,641,318

Wellington 894,538 6,391,847 7,286,385 (44,237) 1,823,384 9,065,532

Total 14,668,596 82,113,828 96,782,424 (15,705,332) 15,705,332 96,782,424

3.4. Price setting and the allocation of target revenue

3.4.1. Target revenue


2.4.3(3) State the target revenue expected to be collected for the pricing

year to which the pricing methodology applies;


19

Vector sets its prices to recover an amount less than the Allowable Notional Revenue under

the GDPP. Compliance with the Allowable Notional Revenue requirement is determined

using current year prices multiplied by quantities lagged by two years. Once price are set

to comply with the GDPP, Vector then determines how much revenue these prices will

deliver based on forecast quantities in the forthcoming pricing year (target revenue). Due

to the difference in quantities between the GDPP and target revenue the amount of target

revenue differs from the amount of Allowable Notional Revenue under the GDPP. Target

revenues for the 2015 pricing year are included in Figure 14 below.

Figure 14 Determining target revenue

Allowable notional revenue 90,726,779

Pass-through and recoverable costs 3,907,272

Subtotal 94,634,050

Pricing and quantity adjustments 2,148,374

Target revenue from prices 96,782,424

The post-allocation adjustments occur as part of the price setting process described in

section 3.4.2 below.

3.4.2. Setting prices

Prices do not mechanistically flow from cost allocations. A decision must be made on the

appropriate fixed and variable charges based on the cost allocations. Following

stakeholder consultation, for the 2016 pricing year Vector set:

A Throughput Fee (TPF) of $0.06/GJ across all standard consumers; and

A Capacity Reservation Fee (CRF) for each region.

The TPF and the CRF have been increased by 0% and 17% respectively for the 2016

pricing year, with the exception of the Frankley Road Pipeline where the TPF has increased

by 13%.

The CRF is expressed in whole dollars and is generally set at a level that will comply with

the GDPP and recover approximately the same target revenue as implied by the cost

allocations plus a pro-rata allocation of pass-through costs. The two exceptions to this are

Auckland and North Waikato where the CRF was set to avoid creating artificial incentives

for capacity nominations and consumer location decisions across these two regions. The

outcome of this is the regional allocations presented in section 3.4.3 below.

Setting the CRF in whole dollar terms means that prices will not precisely recover the

Allowable Notional Revenue plus pass-through costs. To ensure that Vector does not

breach the GDPP, the CRFs are set at a level that will slightly under-recover Allowable

Notional Revenue.

3.4.3. Target revenue by pricing region


2.4.3(6) Where applicable, describe the method used by the GTB to allocate the

target revenue among consumers, including the numerical values of the

target revenue allocated to consumers and the rationale for allocating it in

this way;


20

The target revenue for gas transmission services is not directly allocated to consumers.

Instead, it is allocated using the cost allocations described in Sections 3.2 and 3.3 above,

and subject to the pricing adjustments described in section 3.4.2. It is neither appropriate

nor possible for Vector to publicly disclose the target revenue for individual consumers.

The cost allocation approach described above allocates costs to Connection Points and

Pricing Regions; multiple shippers may take delivery at any given Connection Point or

Pricing Region, and it is the allocation for the Pricing Region that is relevant. The outcome

of the pricing methodology is the allocation between Pricing Regions shown in Figure 15.

Figure 15 Target revenue by pricing region

Pricing region Target revenue

from prices (Pi2016,Qi2016)

Northland $4,449,667

Auckland $28,632,935

Waikato North $4,846,863

Hamilton $1,251,101

Waikato South $8,785,496

Western Bay of Plenty $2,145,785

Eastern Bay of Plenty $8,931,312

Taranaki $16,990,087

Manawatu-Wanganui $3,551,072

Hawke’s Bay $6,734,697

Wellington $10,463,409

Target Revenue $96,782,424

3.4.4. Revenue by price component


2.4.3(7) State the proportion of target revenue (if applicable) that is collected

through each price component as publicly disclosed under clause 2.4.18.

The Gas Transmission Information Disclosure Determination 2012 defines “Price

Component” as the various tariffs, fees and charges that constitute the components of the

total price paid, or payable, by a consumer. The Price Components for Vector’s gas

transmission pricing are specified in the VTC. The price components are:

a Capacity Reservation Fee (CRF) based on an annual reservation of GJ capacity;

a Fixed Fee included as a component of some non-standard contracts;

a Throughput Fee (TPF) based on GJ consumption; and

an Overrun Fee set equal to 10 times the CRF divided by 365 days.


21

The proportion of revenue recovered by each price component is shown in Figure 16. The

variable component of Vector’s target revenue is comprised of Throughput Fees and

Overrun Fees, and is equal to 9% of revenue.

Figure 16 Proportion of target revenue by price component

Price component Target revenue Proportion

Capacity Reservation Fees (CRF) $68,336,041 70.6%

Fixed Fees $14,497,383 15.0%

Throughput Fees (TPF) $5,239,290 5.4%

Over-run Fees $3,686,583 3.8%

Interruptible Contracts $5,023,127 5.2%

$96,782,424 100%

3.5. Price changes


2.4.3(5) If prices have changed from prices disclosed for the immediately

preceding pricing year, explain the reasons for changes, and quantify the

difference in respect of each of those reasons;

From 1 October 2015, weighted average gas transmission prices have increased by 2.2%.

This change is a result of a combination of increases to pass through and recoverable

costs, a CPI increase to the transmission component of prices and changes to quantities.

The CPI increase to the transmission component of prices for the pricing year 1 October

2015 to 30 September 2016 pricing year is 0.9%. This results in an increase in the total

weighted average prices by 0.8%.

Figure 17 below shows the price changes by pricing region. To calculate changes in

average price, target revenue from 2016 prices has been recalculated using updated

quantities (Qi2014). The final column of Figure 17 shows the total percentage change in

prices for each pricing region, by applying the quantities Qi2014 to prices.

The GTPP allows Vector to recover pass-through and recoverable costs. For the 2016

pricing year, pass-through costs are $3,907,272 which is an increase of $1.9m from the

previous year. The increase to pass-through and recoverable costs represents an increase

of 1.4% to the total weighted average prices.


22

Figure 17 Price changes by pricing region

Pricing region Notional revenue Price change

Pi2016,Qi2014 Pi2015,Qi2014

Northland $4,328,986 $4,016,794 8%

Auckland $27,856,371 $33,475,242 -17%

Waikato North $4,715,409 $4,186,634 13%

Hamilton $1,217,169 $1,056,153 15%

Waikato South $8,547,221 $7,343,629 16%

Western Bay of Plenty $2,087,588 $1,794,508 16%

Eastern Bay of Plenty $8,689,083 $7,434,739 17%

Taranaki $16,529,292 $15,447,651 7%

Manawatu-Wanganui $3,454,762 $2,975,900 16%

Hawke’s Bay $6,552,042 $5,640,823 16%

Wellington $10,179,627 $8,753,550 16%

Notional revenue $94,157,552 $92,125,622 2%

Price change differences between regions, when compared with the uniform changes to

standard prices, arise due to the impact of changes to non-standard prices under their

respective contractual requirements.


23

Section 4 Consistency with pricing principles


2.4.3(2) Demonstrate the extent to which the pricing methodology is consistent

with the pricing principles and explain the reasons for any inconsistency

between the pricing methodology and the pricing principles;

4.1. Pricing principles

The pricing principles are specified in clause 2.5.2 of the Gas Transmission Services Input

Methodologies Determination 2010 (Commerce Commission Decision 712, 22 December

2010). Those pricing principles are:

1) Prices are to signal the economic costs of service provision, by-

a) being subsidy free, that is, equal to or greater than incremental costs and less

than or equal to standalone costs, except where subsidies arise from

compliance with legislation and/or other regulation;

b) having regard, to the extent practicable, to the level of available service

capacity; and

c) signalling, to the extent practicable, the effect of additional usage on future

investment costs.

2) Where prices based on ‘efficient’ incremental costs would under-recover allowed

revenues, the shortfall is made up by prices being set in a manner that has regard

to consumers’ demand responsiveness, to the extent practicable.

3) Provided that prices satisfy (1) above, prices are responsive to the requirements

and circumstances of consumers in order to-

a) discourage uneconomic bypass; and

b) allow negotiation to better reflect the economic value of services and enable

consumers to make price/quality trade-offs or non-standard arrangements for

services.

4) Development of prices is transparent, promotes price stability and certainty for

consumers, and changes to prices have regard to the effect on consumers

4.2. Principle #1: Economic costs of service provision

4.2.1. Subsidy-free pricing

Prices are said to be “subsidy-free” when they are not less than incremental cost (IC) and

are not greater than stand-alone cost (SAC). Incremental costs for a consumer (or group

of consumers) are those costs that are only incurred because of that consumer’s (or group

of consumers’) connection to and use of the gas transmission system. Stand-Alone Cost is

the cost of a gas transmission system providing service to just that consumer (or group of

consumers).


24

The revenue allowed under the GDPP includes an allowance for certain costs (such as

administration costs) that is based on an allocation of common and shared costs across

Vector’s regulated businesses rather than an estimate of the magnitude of those costs on a

stand-alone basis. This means that the SAC for the provision of gas transmission services

is higher than the Allowable Notional Revenue under the GDPP. This also means that, in

aggregate, prices set to recover the Allowable Notional Revenue are, by definition, less

than the SAC for the provision of gas transmission services.

At a theoretical level, demonstrating that prices are subsidy-free requires that the

regulated supplier demonstrates that, for every consumer and every consumer group, the

price is not less than the incremental cost of supplying that consumer or consumer group

and is not greater than the SAC of supplying that consumer or consumer group.

Stand-alone cost

Stand-alone cost (SAC) is normally defined as the cost of providing a service or a group of

services and nothing else. In a perfectly competitive market, goods are perfect substitutes,

so the cost of the alternative is the cost of obtaining exactly the same good or service

elsewhere. In the context of gas transmission, this would mean the construction of another

gas transmission pipeline. In a workably competitive market however, goods are not

necessarily perfect substitutes, and an alternative energy or fuel source might provide an

equivalent service. In the case of gas (which is a discretionary fuel), consumers can

choose from a number of alternative sources of delivered energy.

Pricing up to the cost of a dedicated pipeline built specifically for a particular group of

consumers is likely to result in prices that are much higher than the true cost of the

alternative for many users, and this would likely lead to disconnection. In practice, then,

estimating the ‘true’ upper bound on prices requires information on the costs and bypass

options of its consumers (alternative fuels plus alternative transmission connections

including bypass to the Maui pipeline).

To establish the appropriate upper bound for prices at each Connection Point, Vector has

adopted the lesser of:

the traditional “alternative network” SAC; and

the stand alone cost of providing the same delivered energy from an alternative

fuel source (we refer to this as the “alternative fuel SAC”).

It is important to note that Vector has estimated SAC at individual CPs and not at all

combinations of CPs. In this respect the SAC should form a guide only and is not

definitive. In some instances other network solutions may yield a lower SACs across a

combination of CPs, and a more thorough investigation might be appropriate as part of the

non-standard contracting process (see Section 5).


25

Alternative network SAC

The alternative network SAC represents a dedicated theoretical transmission system which

can provide the same current transmission service to a single Connection Point. The

alternative network SAC includes a return on and of all network and non-network assets,

indirect costs, maintenance costs, compressor and heater fuel costs. The SAC analysis is a

highly theoretical exercise involving the construction of hypothetical networks to provide

service to each consumer or consumer group – this is a highly labour-intensive exercise

that generally (but not always) yields an average SAC higher than the SAC for the system

as a whole.2

Theoretical transmission system assets: The assets (or System Fixed Assets (SFA)) for

each Connection Point are assumed to be a stand-alone network between the current

receipt point and the Connection Point. The assets consist of:

a single pipe following the same route as the existing network but sized to only

supply the Connection Point

one or more DPs sized to supply the current maximum design flow at the

connection point

The theoretical pipe size is estimated by means of a simplified general gas flow formula.

Replacement cost of theoretical transmission network assets: The replacement cost of

network assets is based on the annualised SAC pipeline and delivery point replacement

cost rates. An average allocation of all other network assets including special feature

costs, easement costs, compressor and all other types of stations costs are included in the

pipeline replacement cost rate.

Replacement cost of theoretical non network assets: An estimate of the non-network

assets (or Non System Fixed Assets (NSFA)) is based on the NSFA of the Vector

transmission business. Each Connection Point is allocated a replacement cost equal to the

total NSFA value of the Vector transmission business divided by the total number of

Connection Points.

Expenses are comprised of indirect costs, fuel costs, and maintenance costs:

Indirect costs: An estimate of the indirect costs for the connection Point is based

on the total indirect costs of the Vector transmission business. Each Connection

Point is allocated an indirect cost equal to the total indirect costs of the Vector

transmission business divided by the total number of Connection Points.

Fuel costs: Compressor and heater fuel costs are determined by multiplying the

derived compressor and heater fuel rates with the total volume at the connection

Point. These costs only apply if the Connection Point has been identified as

requiring compression and/or heating.

2 Because of the economies of scale inherent in gas transmission networks, the

average per-consumer SAC for a consumer will generally be greater than the average per-

consumer SAC for a group of consumers, which in turn will generally be greater than the

average per-consumer SAC for the network as a whole. If prices are less than the SAC for

the network as a whole then they are likely to be less than SAC for any given consumer or

group of consumers. The exception to this is where a large consumer is located close to the

gas transmission line and it would be viable to bypass the existing gas transmission system.

This is addressed separately under Pricing Principle 3.


26

Maintenance costs: Maintenance on network assets is determined by multiplying

the derived maintenance rate for all assets with the total replacement cost of the

theoretical system.

Alternative fuel SAC

The approach to calculating the alternative fuel SAC was described in Section 2.2.

Incremental cost

The incremental costs (IC) of each Connection Point are determined by exactly the same

“but for” test that is used to identify Connection Costs. Two estimates of IC are

calculated: short run incremental costs (SRIC) and long run incremental costs (LRIC). The

SRIC include compressor fuel, heater fuel and maintenance on the dedicated assets

identified by means of the “but for” test. The LRIC includes the SRIC plus a return on and

return of the dedicated assets identified by means of the “but for” test. The relationship

between Connections Costs, Incremental Costs, and Directly Attributable Costs is:

Connection Costs = Long Run Incremental Costs = Costs Directly Attributable

If consumers are paying a price at least equal to SRIC then they are covering the

immediate direct costs incurred in supplying them with gas, and in the short term it is

beneficial to retain those consumers. Over the longer term consumers should pay a price

at least equal to LRIC so that they cover the full cost of providing supply, including the

cost of the assets required to connect to the wider system.

Vector’s application of the test

As described in section 2.2, as part of the price-setting process Vector compares proposed

prices against the least-cost alternative, whether that is a standalone network or an

alternative energy source such as coal or bottled LPG.

Vector cross-checked the individual revenue at each DP based on provisional prices. This

allows an assessment of the extent to which uniform CRFs within zones create revenues

that fall outside the IC-SAC band at individual DPs. This is illustrated in Figure 18.

Prices at some CPs have historically been less than IC. While the overall framework for

Vector’s pricing has improved alignment with the pricing principles, there are however a

number of CPs where the reduction in prices has either worsened the extent to which

prices are below incremental costs, or has moved prices previously in the subsidy free

range to a point below incremental costs. Generally the revenue from these DPs is low and

we propose further work targeted at assessing each CP and the potential mitigations that

may be employed.


27

Figure 18 Revenues from prices by CP and subsidy free ranges


28

Figure 19 Revenues from prices by pricing region


29

4.2.2. Available service capacity and future investment costs

There are no constraints on available service capacity in the gas transmission system that

impact on the economic cost of service provision. Indeed, given the level of available

service capacity, it is appropriate that pricing is set in a manner that encourages greater

use of the gas transmission system.

There are no significant future investment costs that impact on the economic cost of

service provision.

4.3. Principle #2: Recovery of any shortfall

Pricing Principle 2 requires that:

Where prices based on ‘efficient’ incremental costs would under-recover allowed

revenues, the shortfall is made up by prices being set in a manner that has

regard to consumers’ demand responsiveness, to the extent practicable.

Recovery of any shortfall in a manner that “has regard to consumers’ demand

responsiveness” suggests the application of Ramsey Pricing. While Ramsey Pricing (which

involves pricing higher to those less price responsive) is a useful and well accepted

guideline for the recovery of allowed revenues above IC, it is extremely difficult to apply in

practice as the information required (meaningful demand responsiveness information) is

not readily available. It is also worth emphasising that even if Vector knew something

about the demand responsiveness of consumers, Vector contracts with Shippers (together

with large directly connected consumers) and is therefore generally not able to price

discriminate across consumer groups based on demand elasticities. This information can

be used however to inform the approach to non-standard contracts which use an

estimated bypass cost as a guide (see Section 5).

Given the practical difficulties inherent in implementing a Ramsey pricing approach, Vector

has instead sought to recover any revenue shortfall in as least-distortionary manner as

possible. Vector considers that this captures the intent of Pricing Principle #2. Accordingly,

the cost of shared assets has been allocated using Maximum Flow as an allocator, which

reflects the underlying cost driver for the network. The resulting cost allocations provide

improved incentives to utilise the existing gas transmission system in areas that were

disadvantaged by the previous distance-based regime. Further, prices have been set on a

regional basis to ensure there are no incentives to “game” capacity reservations between

neighbouring DPs.

4.4. Principle #3: Responsive to requirements of consumers

4.4.1. Prices discourage uneconomic bypass

Discouraging uneconomic bypass is an extremely important commercial objective for

Vector. Gas transmission services have to compete with alternative fuel and energy

sources such as electricity, LPG, wood fires, coal, and solar heating.

Traditionally this principle has been interpreted to mean that prices should not be so high

for any consumer that it becomes economic for a competitor to supply that consumer

using an alternative network supply. This principle is based on the economic rationale that

it is more efficient for one natural monopoly gas network to serve all consumers itself

because of economies of scale/density. If another network tried to compete with the gas

network side-by-side it would be less efficient as the economies of scale for those

consumers would be lost and total cost would increase.


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However, uneconomic bypass may also occur where a consumer uses an alternative

energy source instead of natural gas and the incremental social costs of the alternative are

higher than the incremental social costs of using the gas transmission system. Vector has

included alternative energy sources in our development of SACs and considers these in the

development of standard prices. Notwithstanding this uneconomic bypass may still occur.

Where Vector is aware of such instances, for example through the consumer approaching

Vector, we addresses these through the application of non-standard prices as described in

4.4.2 below.

4.4.2. Negotiation for non-standard prices

Vector considers that the best way to allow consumers to negotiate differing levels of

economic value from a service or to mitigate against uneconomic bypass is through non-

standard contracts. Large consumers are able to negotiate with Vector for different terms

and conditions as long as it is commercially viable and possible for Vector to provide the

service.

Typical examples of consumers negotiating to realise economic value of different specific

service include reinforcement of the network to allow for greater capacity and the

installation and management of specialist equipment and connections. Contracts have

been negotiated on non-standard pricing structures to allow consumers to manage their

risk, including adjustment in prices to allow for atypical demand loads (e.g. seasonal use

patterns) or a preference for pricing that is largely, if not wholly, fixed. Vector is also

willing to offer different terms for different length contracts.

Please refer to Section 5 for Vector’s policy regarding pricing for non-standard contracts.

4.5. Principle #4: Pricing process


Development of prices is transparent, promotes price stability and certainty for

consumers, and changes to prices have regard to the effect on consumers

The development of Vector’s GTPM was subject to a lengthy consultation process,

described in Section 1.5. This consultation process was an important part of Vector’s

compliance with Pricing Principle #4. More information on the consultation and process is

available on Vector’s website at: http://www.vector.co.nz/gas/gas-transmission-pricing-

methodology

4.5.1. Development of prices is transparent

The development of the new GTPM has been conducted in a transparent manner with

consumer consultation conducted at regular intervals. The approach adopted has been

adopted as appropriate based on consumer feedback.

Furthermore, within the GTPM costs are clearly identified and allocated on a simple and

transparent basis.

4.5.2. Price stability and certainty

The revised cost allocation methodology reduces the likelihood that changes in consumer

behaviour will result in significant changes to cost allocations between Connection Points.

The use of Pricing Regions also eliminates the opportunity for arbitrage between

Connection Points. Together, these changes mean that prices will be more stable over

time.

http://www.vector.co.nz/gas/gas-transmission-pricing-methodology

http://www.vector.co.nz/gas/gas-transmission-pricing-methodology


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4.5.3. Effect on consumers

Vector is particularly conscious of the effect of its pricing on consumers and seeks to

implement a pricing structure that provides appropriate incentives for consumers to

connect to the gas transmission system and continue to use natural gas. Throughout the

GTPM Review process Vector has actively modified its proposals to take account of

consumer feedback.


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Section 5 Pricing for non-standard contracts

This section describes Vector’s approach to setting prices for non-standard contracts.

5.1. Extent of non-standard contracts

2.4.5(1) Describe the approach to setting prices for non-standard contracts,

including-

(a) the extent of non-standard contract use, including the value of target

revenue expected to be collected from consumers subject to non-standard

contracts;

In certain circumstances Vector’s published standard prices may not adequately reflect the

actual costs of supplying a consumer, reflect the economic value of the service to the

consumer or address the commercial risks associated with supplying that consumer. In

addition to standard published prices, the GTPM also includes supplementary (non-

standard) agreements and interruptible agreements (a form of supplementary agreement)

as follows:

a) Supplementary (non-standard) agreements – a bi-lateral agreement between Vector

and a shipper that amends parts of the Vector Transmission Code (VTC) for the

purposes of delivery of gas to:

i. A specific consumer and/or specific site; or

ii. A specific delivery point.

b) Interruptible capacity – a form of supplementary agreement which is provided under

the terms and conditions of an interruptible agreement.

These contracts allow tailored or specific prices and contractual terms to be applied to

individual points on the transmission system.

There are 34 consumers subject to non-standard contracts with an expected target

revenue of $26,260,393.

5.2. Criteria for non-standard contracts

2.4.5(1)(b) Describe the approach to setting prices for non-standard

contracts, including-

how the GTB determines whether to use a non-standard contract, including

any criteria used;

Vector has a published policy that provides a general guideline of the steps that Vector will

follow and the factors that it will take into account when deciding whether or not to offer a

non-standard (supplementary agreement) on the transmission system. This document

(Supplementary Agreements Policy (March 2012)) can be found on OATIS at:

https://www.oatis.co.nz/Ngc.Oatis.UI.Web.Internet/Common/Publications.aspx

Vector determines whether a consumer is eligible for non-standard pricing on a case by

case basis subject to the Supplementary Agreements Policy contained in the Vector

Transmission Code.

https://www.oatis.co.nz/Ngc.Oatis.UI.Web.Internet/Common/Publications.aspx


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Between 1 January 2008 and 30 June 2012 during the price controls under the Act, Vector

transitioned consumers on non-standard contracts to a one-year term because of a high

level of uncertainty about what the conditions of the GDPP might be. Now that the GDPP

is in place, Vector is continuing to offer one-year contract terms, but may negotiate longer

terms on a case-by-case basis.

5.3. Methodology for non-standard prices

2.4.5(1) Describe the approach to setting prices for non-standard contracts,

including-

(c) any specific criteria or methodology used for determining prices for

consumers subject to non-standard contracts, and the extent to which

these criteria or that methodology are consistent with the pricing principles;

The prices for non-standard contracts are set to ensure that Vector is able to recover the

costs of supplying non-standard consumers. These are determined on a case by case basis

and the nature of prices is determined specific to the circumstances of the

shipper/consumer. However, in all cases prices are tested to ensure that they are not less

than incremental cost and not greater than standalone costs, given the characteristics of

the consumer.

When an existing contract is due for renewal, Vector assesses the pricing in that contract

and prices are either set to standard, or renegotiated.

The flexible approach to pricing for non-standard contracts ensures that compliance with

the pricing principles is enhanced, as demonstrated in Figure 20 below.

Figure 20 Compliance of non-standard pricing with the pricing principles

Pricing principle Extent of compliance without non-standard pricing

Extent of compliance with non-standard pricing

1) Prices are to signal the economic costs of service provision, by-

a) being subsidy free, that is, equal to or greater than incremental costs and less than or equal to standalone costs, except where subsidies arise from compliance with legislation and/or other regulation;

b) having regard, to the extent practicable, to the level of available service capacity; and

c) signalling, to the extent practicable, the effect of additional usage on future investment costs.

Prices are subsidy-free

There are no capacity constraints to reflect in current pricing. Price structure is set to generally encourage use of spare capacity. However, some spare capacity may be unused in the absence of non-standard pricing if the consumer disconnects from the gas transmission system.

Prices remain subsidy-free

Compliance enhanced because non-standard pricing ensures that consumers that would otherwise disconnect from the gas transmission system will remain connected, use available capacity that would otherwise be unutilised. These consumers will continue to pay some portion of the shared costs of the gas transmission system at least equal to or above incremental costs, providing a benefit to all connected parties.


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Pricing principle Extent of compliance without non-standard pricing

Extent of compliance with non-standard pricing

2) Where prices based on ‘efficient’ incremental costs would under-recover allowed revenues, the shortfall is made up by prices being set in a manner that has regard to consumers’ demand responsiveness, to the extent practicable.

If a consumer disconnects because standard prices exceeded their “reservation cost” then those prices did not reflect the demand-responsiveness of that consumer.

Compliance is enhanced because the demand-responsiveness of a price-sensitive consumer has been taken into account by the non-standard pricing.

3) Provided that prices satisfy (1) above, prices are responsive to the requirements and circumstances of consumers in order to-

a) discourage uneconomic bypass; and

b) allow negotiation to better reflect the economic value of services and enable consumers to make price/quality trade-offs or non-standard arrangements for services.

All prices are subsidy-free so meet (1) above.

Prices have been explicitly set to account for the cost of alternative sources of energy for the average consumer in a category, but do not account for the specific circumstances of all consumers.

Prices continue to be subsidy-free so meet (1) above.

Compliance is enhanced because non-standard pricing allows differential prices to be set for the specific consumers where bypass is viable or would otherwise be uneconomic.

Compliance is enhanced because non-standard pricing allows prices for gas transmission services to be customised to reflect the

economic value of gas transmission services to specific consumers, and allows the consumer to make quality/price trade-offs.

4) Development of prices is transparent, promotes price stability and certainty for consumers, and changes to prices have regard to the effect on consumers

Compliance is enhanced because allowance can be made for the effect on particular consumers whose circumstances make them more sensitive to prices.

5.4. Obligations in respect of service interruptions

(2) Describe the GTB’s obligations and responsibilities (if any) to consumers

subject to non-standard contracts in the event that the supply of gas

transmission services to the consumer is interrupted. This description must

explain-

(a) the extent of the differences in the relevant terms between standard

contracts and non-standard contracts;

(b) any implications of this approach for determining prices for consumers

subject to non-standard contracts.

Vector’s obligations to consumers and shippers under standard and non-standard contracts

for transmission services are identical, excepting those non-standard contracts that are

Interruptible Agreements.


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Firm transmission capacity provided under shippers’ transmission services agreements

(reserved capacity) ranks equally with firm capacity provided under non-standard

contracts (supplementary capacity) in the event of any emergency or other event that

affects Vector’s ability to provide transmission capacity. On the other hand, Vector’s

contracts require the system operator (Vector) to use all reasonable endeavours to curtail

consumers on interruptible agreements before restricting consumers’ reserved capacity or

supplementary capacity.

The main difference between firm transmission capacity and interruptible capacity is the

probability of curtailment. In the event curtailment is required, the effect on the consumer

is similar under all contracts:

a) if compelled to curtail reserved capacity or supplementary capacity, Vector is generally

obliged to rebate fixed transmission fees to affected consumers for the period of the

curtailment;

b) under an interruptible agreement, the consumer will not be charged for its interruptible

capacity to the extent of a curtailment.


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Section 6 Compliance matrix

The table below is included to demonstrate how this disclosure complies with the Gas Transmission Information Disclosure 2012.

2.4.1 Every GTB must publicly disclose, before the start of each pricing year, a pricing methodology which-

See individual clauses below.

(1) Describes the methodology, in accordance with clause 2.4.3, used to calculate the prices payable or to be payable;

Section 3

(2) Describes any changes in prices and target revenues; Section 3

(3) Explains, in accordance with clause 2.4.5 of this section, the approach taken with respect to pricing in non-standard contracts; and

Section 5

(4) Explains whether, and if so how, the GTB has sought the views of consumers, their expectations in terms of price and quality, and reflected those views in calculating the prices payable or to be payable. If the GTB has not sought the views of consumers, the reasons for not doing so must be disclosed.

Section 4.5.3

2.4.2 Any change in the pricing methodology or adoption of a different pricing methodology, must be publicly disclosed at least 20 working days before prices determined in accordance with the change or the different pricing methodology take effect.

N/A

2.4.3 Every disclosure under clause 2.4.1 of this section must- See individual clauses below.

2.4.3(1) Include sufficient information and commentary for interested persons to understand how prices were set for consumers, including the assumptions and statistics used to determine prices for consumers;

Section 3

2.4.3(2) Demonstrate the extent to which the pricing methodology is consistent with the pricing principles and explain the reasons for any inconsistency between the pricing methodology and the pricing principles;

Section 4


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2.4.3(3) State the target revenue expected to be collected for the pricing year to which the pricing methodology applies;

Section 3.4.1

2.4.3(4) Where applicable, identify the key components of target revenue required to cover the costs and return on investment associated with the GTB’s provision of gas transmission services. Disclosure must include the numerical value of each of the components;

Section 3.3.1

2.4.3(5) If prices have changed from prices disclosed for the immediately preceding pricing year, explain the reasons for changes, and quantify the difference in respect of each of those reasons;

Section 3.5

Revenue by Consumer Group

2.4.3(6) Where applicable, describe the method used by the GTB to allocate the target revenue among consumers, including the numerical values of the target revenue allocated to consumers and the rationale for allocating it in this way;

Section 3.4.3

Revenue by Price Component

2.4.3(7) State the proportion of target revenue (if applicable) that is collected through each price component as publicly disclosed under clause 2.4.18.

Section 3.4.4

Effect of Pricing Strategy

2.4.4 Every disclosure under clause 2.4.1 above must, if the GDB has a pricing strategy-

(1) Explain the pricing strategy for the next 5 pricing years (or as close to 5 years as the pricing strategy allows), including the current pricing year for which prices are set;

(2) Explain how and why prices are expected to change as a result of the pricing

strategy;

(3) If the pricing strategy has changed from the preceding pricing year, identify the changes and explain the reasons for the changes.

Vector’s Board of Directors have not recorded in writing any decision on plans or strategies to amend or develop prices beyond the pricing year ending on 30 September 2016 and accordingly have not approved a pricing strategy.

Prices for Non-Standard Contracts

2.4.5 Every disclosure under clause 2.4.1 above must-


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(1) Describe the approach to setting prices for non-standard contracts, including-

(a) the extent of non-standard contract use, including the value of target revenue expected to be collected from consumers subject to non-standard contracts;

(b) how the GTB determines whether to use a non-standard contract, including any criteria used;

(c) any specific criteria or methodology used for determining prices for consumers subject to non-standard contracts, and the extent to which these criteria or that methodology are consistent with the pricing principles;

(2) Describe the GTB’s obligations and responsibilities (if any) to consumers subject to non-standard contracts in the event that the supply of gas transmission services to the consumer is interrupted. This description must explain-

(a) the extent of the differences in the relevant terms between standard

contracts and non-standard contracts;

(b) any implications of this approach for determining prices for consumers subject to non-standard contracts.

Section 5

Section 5.1

Section 5.2

Section 5.3

Section 5.4


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pricing methodology for gas transmission services · price component: the various tariffs, fees and...

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